Hassan Dehghanpour University of Alberta

1. Analysis and Treatment of Flowback Water
for Reservoir Characterization and Production Optimization
May, 2022
Hassan Dehghanpour
University of Alberta

2. 2
Outline
1. What can we do with flowback data and samples?
2. What can we learn from water flowback analysis?
3. What happens when fracturing water interacts with reservoir rock and fluid?
4. Can in-situ water-rock interactions be controlled?
5. How does the treatment process affect rock wettability?
6. Can the treatment process be optimized for “Enhanced Oil Recovery While
Fracturing”?

3. 3
How can flowback data and samples be analyzed?
Flowback Volumetric Analysis
Flowback Chemical Analysis

4. 4
Flowback Data Recognition and Digitization
Keywords’ Frequency in PDF and PAS Reports
• Collect Pressure-Test reports of 40,000 MFHWs
completed in WCSB (from geoSCOUT).
• Digitize PDF reports using optical character
recognition (OCR).
• Extract text (keywords) from PAS and PDF files.
• Estimate keywords’ frequency (𝑥𝑖)
• Apply feedforward ANN to classify (flag)
flowback data/reports.
• Develop an automation algorithm to extract
flowback pressure, rate and choke-size from
identified flowback reports.
• Process the extracted data for quality control
and store into MySQL database
𝒙𝟏
𝒙𝟐
𝒙𝒏
𝒀𝒆𝒔
𝑵𝒐
∑ | 𝒇
𝒃𝟐𝑨
𝒃𝟐𝑩
⋮
𝑤1
𝑤2
𝑤3

5. 5
Well Productivity and Completion Intensity
*Barrel of oil equivalent (BOE) = 6,000 ft3
Moderate (20%) increase in BOE
production in the last 10 years.

6. 6
Is Fracturing Water Efficiently Used?
Since 2015, the
more water volume
injected the less
water recovery!
Is the current completion-design approach efficient enough?
Completion Intensity
High = large volume of water
injection per stage , more stages
and high proppant concentration.

7. 7
The Efficiency of Fracturing-water Recovery
• 56 billion gallons of water was used for
the hydraulic fracturing operations in
WCSB in the last 10 years.
• Only 26 billion gallons recovered (46%)
• What are the key reasons for the
variation in water-recovery efficiency?
Water-recovery distribution map generated by:
1. Collecting flowback and production data of 40,000
MFHWs completed in WCSB and collected from
geoSCOUT database
2. Applying ordinary kriging for spatial interpolation and
contouring

8. Predicting Ultimate Water Recovery from Flowback
8
Flowback Post Flowback
Harmonic Decline Model
Ultimate Water
Recovery Volume
(a) (b)
Flowback Post Flowback
Harmonic Decline Model
Ultimate Water
Recovery Volume
(a) (b)
Harmonic Decline model can predict ultimate
water recovery volume
Early-time flowback water rate obeys
Harmonic Decline trend

9. 9
A Horn River Case Study
Ghanbari et al., 2013. (SPE-157165)

10. 10
Distinct Trends in Salinity Profiles of
Flowback Water versus Time
Ghanbari et al., 2013. (SPE-157165)
0
20000
40000
60000
80000
0 2000 4000 6000 8000
Salinity
(ppm)
Cumulative Water Production (m3)
MU-R1 OP-R1 EV-R1
Continuous
increase
Plateau
at late times

11. 11
Barium Vein on Surface of a Natural Fracture
Left: Picture of a barium vein found on the surface of a natural fracture in a
sample from the Ev formation.
Right: The corresponding barium map from EDS analysis of the barium vein.
Ba
Barium Vein
5mm
Zolfaghari et al., (2016). Laboratory and field analysis of flowback water from gas shales

12. 12
Barium Vein on Surface of a Natural Fracture
Barium Source
Natural Fractures
0
500
1000
1500
2000
0 300 600 900 1200
Concentration
(ppm)
Time (hr)
Ba2+ (Ev)
Larger Slope
0
500
1000
1500
2000
0 300 600 900 1200
Concentration
(ppm)
Time (hr)
Ba2+ (Mu)
Smaller Slope
0
500
1000
1500
2000
0 300 600 900 1200
Concentration
(ppm)
Time (hr)
Ba2+ (OP)
Smaller Slope
Connectivity between
natural & induced fractures
Barium concentration profile
More complex
More simple
More simple
Zolfaghari et al. (2016), Fracture characterization using flowback salt-concentration transient (SPE-168598-PA)

13. 13
A Horn River Well Pad: Low Fracturing Water Recovery
0
100
200
300
400
500
0
500
1000
1500
2000
0 100 200 300 400
Water
Rate
(m
3
/d)
Time (hrs)
Xu et al. (2015)
Lan et al. (2014)
Gas
Water
Gas
Rate
(Mm
3
/d)
0
10
20
30
40
50
60
70
80
90
100
0 500 1000
Load
Recovery,
%
Time (hrs)
well B well E
well G well K
well N well Q

14. 14
Where Did All the Frac Water Go?
 Is it left in fractures?
 Did it imbibe into the shale matrix?
……and what are the implications to long term production?
Gas Bubbles

15. 15
What happens when fracturing water
interacts with reservoir rock and fluid?

16. A Horn River Case Study
Imbibition Experiments
SPE-171620-PA
Oil Brine
Drilling Twin Plugs
Spontaneous Imbibition
Imbibition Profiles
0
20
40
60
80
100
0 400 800 1200 1600 2000
Imbibed
Volume
(%PV)
Time (hrs)
Oil
Brine

17. 17
Measuring Water Imbibition and Salt Diffusion
EC & ICP-MS
DI Water Brine Fracturing water with
additives or treated produced
water
Balance
Computer
SPE-185078-MS

18. 18
The Role of Clays
SPE-167165-MS
Clay content
Role of Clays
Shale samples are disintegrated
after water imbibition!
Clay content
Before
Imbibition
After
Imbibition
0
0.1
0.2
0.3
0.4
0.5
0.6
0 10 20 30
Imbibed
volume/Surface
area
(cc/cm
2
)
Time (Hours)
Fort Simpson
Muskwa
Otter Park
18

19. 19
The Role of Salinity
Xu and Dehghanpour, 2014. (Energy & Fuels)

20. What happens during shut in period of an oil well?
20
Releasing oil from matrix
by counter-current imbibition?
Formation damage by phase trapping?
Scale formation and precipitation?

21. 21
Simulation of Shut-in Period in Laboratory
Hassan et al., JPSE 2017.
http://www.naturphilosophie.co.uk
1 inch
3
inch
Oil Recovery
Oil
RF
(%OOIP)
0
10
20
30
40
50
60
0 30 60 90 120
Time (days)

22. 22
The Role of Wettability
Oil
RF
(%OOIP)
0
10
20
30
40
50
60
0 30 60 90 120
Time (days)
1 cm
0
10
20
30
40
50
60
0 500 1000 1500
Oil
RF
(%OOIP)
Time (days)
20 40 60
Water-wet
Oil-wet
50%
5%
1 cm
SPE-175157-PA
SPE-185065-PA
Small oil droplets
81.9nm
1000 nm
Organic
Pores

23. 23
What is the role of water chemistry
on wettability and oil recovery?

24. 24
Imbibition Oil Recovery Tests: Surfactant Screening
S1
S2
S3
Tap
S1
S2
S3
Brine

25. Nanoparticles Increase Imbibition Oil Recovery
0
3
6
9
12
15
18
0 500 1000 1500 2000
Oil
RF
(%
initial
oil)
Time (h)
TW+NP1 (2wt%)
TW
TW+NP2 (0.1wt%)
Brine
Enhancing Oil Recovery by Nanoparticles in Frac Water
Nanoparticles
https://www.nanoactiv.com/products/nanoactiv-hrt

26. 26
Wettability alteration by nanoparticle additives: Oil-Wet to Water-Wet
Nanoparticle concentration increasing from 0 (base cases) to 2wt%
Wettability Alteration by Nanoparticle Additives
Fresh Water
Brine

27. 27
How does water treatment affect rock wettability?

28. 28
Electro-Oxidation Technology
Anode (+)
Cathode (-)
Produced
Contaminated Brine
e-
Cl2,HOCl,OCl-,ClO2
Brine with Multiple
Oxidants
OH-, H2O2
No Chemicals
Direct
Kills Bacteria
Precipitates Scale-causing Minerals
Oxidizes Heavy Metals
Softens Produced Water
Indirect
Generates Free Chlorine
(Cl2,HOCl,OCl-), Chlorine Dioxide
(ClO2) and Hydrogen
Peroxide(H2O2)

29. 29
Electro-Oxidation Technology
2. Property
Measurements
3. Contact Angle (CA)
Measurement
4. Imbibition Tests
EO Process
Surface Tension
Density
pH
Viscosity
Interfacial Tension
Core End
Piece
Oil
Droplet
Diffusion of
H+, OH-,
H2O2, HOCl
Oil
Droplet
Untreated
Brine
Treated
Brine
1. Sample
Preparation
(Limiting Conditions)
(Dynamic Conditions)
Core
Treated
Brine
Core
Untreated
Brine

30. 30
Comparative Contact-Angle Results
Rock is less oil-wet in treated formation brine
In untreated
Brine
In treated
brine
CA = 71.8𝑜
CA = 83.0𝑜
Rock
Oil droplet
EO Process
71.8o±4.6o
75.0o±5.1o
84.9o±2.8o
89.6o±3.9o
0
20
40
60
80
100
90,000 ppm FB 40,000 ppm FB
CA
measurements
(Degree)
Untreated brines/solutions Treated brines/solutions
The Effects of Electro-oxidation Process on Tight-Rock Wettability and Imbibition Oil Recovery,
Energy & Fuels, Yanze Zhang, (in Press).

31. 31
Visualizing Contact Angle Change by Adding Oxidants
Core end piece
90000 ppm
NaCl
(volume=60cc) Equilibrated
Oil Droplet
Glass cell
(volume=100cc)
Oil Droplet
Equilibrating
Re-equilibrated
Oil Droplet
Adding
components
Adding individual components (NaOH, HCl, NaOCl and H2O2) to
evaluate wettability alteration

32. 32
The Change in Oil Contact Angle by Adding Oxidants
H2O2 Diffusion NaOCl Diffusion
60
65
70
75
80
0 1 2 3 4
CA
(degree)
Time (hrs)
0
3
6
9
12
0day 3days 6days 9days
H
2
O
2
(ppm)
50
60
70
80
0 1 2 3 4
CA
(Degree)
Time (hrs)
0
30
60
90
120
0day 3days 6days 9days
Active
Chlorine
(ppm)
H2O2 increases contact angle and HOCl decreases contact angle
Initial H2O2: 0 ppm Final H2O2: 10 ppm Initial HOCl: 0 ppm Final HOCl: 100 ppm
Add H2O2
(0.02 ml; 3 wt%)
Add NaOCl
(0.043 ml; 13-15
wt%)
The Effects of Electro-oxidation Process on Tight-Rock Wettability and Imbibition Oil Recovery,
Energy & Fuels, Yanze Zhang, (in Press).

33. 33
Comparing Oil Recovery of Treated and Untreated Brine
33
19.2 % oil recovery factor 22.7 % oil recovery factor
Untreated
Treated

34. 34
Mineral Dissolution and Re-precipitation
Reddish-brown precipitates
• Dissolution of minerals (e.g., pyrite, chlorite, etc.)
• Releasing high-valence cations (e.g., Mg2+, Si2+, Ca2+, Al3+, or Fe3+)
• Re-precipitating at surface (e.g., Fe(OH)3)
Pictures of Core Plugs in Treated Brine

35. 35
A Performance Indicator: Formation Permeability Change
What are the effects of treated
water as fracturing fluid on
pressure profile during leak-off
and flowback?

36. 36
Evaluating the Possibility of Formation Damage
0
200
400
600
800
1000
1200
0 50 100 150 200 250
Pressure
(psi)
Time (hrs)
Injecting fracturing
fluid into the oil
saturated plug
Injecting oil into
the plug from the
other side
Soaking the plug
with fracturing fluid
at high pressure
Leak-off Flowback
0
200
400
600
800
0 40 80
Pressure
(psi)
Time (hrs)
0
200
400
600
800
0 40 80
Pressure
(psi)
Time (hrs)
Permeability
measurement
before Leak-off test
Permeability
measurement after
Flowback test

37. 37
Compatibility of Treated Brine and Friction Reducer
37
Ions in brine (e.g., Calcium, Magnesium, and Ferris ions) can cause the polymer chains to
curl or permanently damage
(Yang et al., 2019)

38. 38
Effect of Salinity on Dynamic Viscosity
38
0
0.5
1
1.5
2
2.5
3
3.5
0 20 40 60 80 100
Shear
Stress
[Pa]
Shear Rate [1/s]
Shear Stress Vs Shear Rate
1
10
100
1000
10000
0 20 40 60 80 100
Viscosity
[mpa.s]
Shear Rate [1/s]
Viscosity vs Shear Rate
FR in DI Water
High salinity gives lower shear stress and viscosity at constant shear rate
FR in DI Water
FR Formation Brine
FR Formation Brine

39. Effect of Salinity on Viscoelastic Properties of Friction Reducers
0.001
0.01
0.1
1
0.1 1 10
Storage
Modulus
[G’]
Loss
Modulus
[G’’]
Angluar Frequency [Rad/s]
High salinity decreases the values of storage and loss modulus
Crossover Frequency
FR in DI Water
FR in Brine
G”
G’
G”
G’

40. Our Laboratory at UofA

41. HPHT Coreflooding System
41
Computer
Accumulator Core holder
Pump

42. HPHT Reactor
42
Chamber
Mixer
Gauge
Heating jacket
Control system

43. HPHT Visualization Cell
Computer
Data acquisition
Visual cell
Camera
Hydraulic oil (HO)
accumulator N2 accumulator
Back pressure
regulator (BPR)
Sampling
chamber

44. Analysis and Treatment of Flowback Water
for Reservoir Characterization and Production Optimization
May, 2022
Hassan Dehghanpour
dehghanpour@ualberta.ca
University of Alberta